CN109751034B - Fracturing sand adding method for oil and gas reservoir - Google Patents
Fracturing sand adding method for oil and gas reservoir Download PDFInfo
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Abstract
The invention relates to a fracturing sand adding method for an oil and gas reservoir, which adopts different fracturing fluid types in a pre-fluid crack making stage and different sand carrying fluid sand adding stages respectively, and uses propping agents with different densities and particle sizes in a matching way, so that the configuration of the propping agents in the whole crack space is optimized, the flow conductivity of the crack is improved, and the fracturing effect is improved. The invention further synergistically optimizes construction parameters such as fracturing fluid discharge capacity, fluid quantity, sand-fluid ratio and the like at different fracturing construction stages, so that the propping agent is uniformly laid in the whole fracture space, the 'filling degree' and 'propping efficiency' of the propping agent in the fracture are improved, the effective flow guiding capacity is improved after the pressure is increased, and the problems of low initial yield, fast yield decrease, short stable production period and the like after the pressure is increased are solved.
Description
Technical Field
The invention relates to the technical field of hydraulic fracturing yield-increasing transformation of oil and gas reservoirs, in particular to a fracturing sand-adding method of an oil and gas reservoir.
Background
The core of the hydraulic fracturing technology comprises two parts, namely fracturing and crack formation, and filling proppant to form a supporting crack with certain flow conductivity. The longer the supporting gap of the crack is and the higher the effective flow conductivity is, the higher the yield after pressing is, and the slower the yield decreasing speed is.
The characteristics of the reservoir itself, the optimal selection of fracturing fluid and proppant, and the optimization of fracturing construction parameters all can affect the effect of sand addition in fracturing.
For example, if the reservoir stratum has high stress, large young modulus and large fluid loss, the fracture width in the fracturing fracture is narrow, so that the resistance of the proppant to enter the fracture is increased, and the problems of no sand addition or difficult sand addition (difficult sand ratio increase and continuous wellhead pressure increase) in the fracturing construction are caused, so that the fracture filling degree is low.
For example, if the viscosity of the fracturing fluid selected at the initial stage of fracturing sand adding is too low, the proppant can be prematurely settled at the bottom of a fracture seam in the process of proppant transportation, so that a large amount of proppant can be prematurely accumulated at the fracture of a near well, so that the fracture of a middle and far well zone can not be effectively supported, and the sand adding profile in the fracture is unreasonable and the sand blocking at the early stage of construction can be caused.
For example, the fracture width is generally relatively narrow at the initial stage of fracturing sand adding, and if the proppant with an excessively large particle size is used for sand adding, on one hand, the proppant has large crack entering resistance at the initial stage of sand adding, so that the construction pressure is high, and the risk of sand removal or early sand blocking is avoided; on the other hand, the large-particle size proppant can only enter and support a main fracture system with a large fracture width, and branch fractures and micro-fracture systems with relatively small fracture widths cannot obtain effective support.
For example, unreasonable fracturing construction parameter selection can also affect fracturing fracture-making and sand-adding effects, unreasonable construction parameters can cause excessive proppant to be accumulated in a fracture near-wellbore area, far-wellbore fracture supporting efficiency is low, the filling degree of a longitudinal space of the whole fracture is low, proppant distribution in a transverse space is extremely uneven, and the like, so that the flow conductivity after fracturing is directly affected.
At present, in the fracturing transformation of compact sandstone and unconventional oil and gas reservoirs, because the type of the adopted fracturing fluid is single, the matching property of the particle size of a propping agent and the width of a fracture is poor, the density of the propping agent is single (the medium-high density accounts for more), and the injection parameters of the fracturing construction process are not reasonable enough, the propping agent is unreasonably distributed in the fracture and the 'propping efficiency' of a far well fracture is low; due to the unreasonable fracture support profile and the low filling degree of the whole fracture proppant, the long-term flow conductivity and the fracture transformation effect of most oil and gas wells are seriously influenced, and the problems of low initial yield after the fracturing, quick yield decrease, short stable production period and the like generally exist.
The optimal situation in fracturing is that on the basis of full crack formation (the central line position of a fracturing crack must be coincident with or basically coincident with the central line position of a reservoir stratum, and the crack formation volume covers the thickness of the effective reservoir stratum to the maximum extent), the fracturing crack formation space is effectively utilized, and sand blockage in the early or middle and later construction periods is not caused in construction, so that the filling degree of proppant in the crack space (the filling degree is the percentage of the volume of proppant to the volume of the crack formation, and the ideal crack filling degree is 100%) is maximized. The higher the filling degree of the crack is, the higher the utilization rate of the fracturing and crack-forming space is; on the contrary, the fracture-making space utilization rate is low, most fracture-making spaces cannot be effectively utilized and supported, and the flow guiding capacity after fracturing is influenced.
Therefore, in the research of the reconstruction of the fracturing of the oil and gas reservoir, the development of a fracturing sand adding method capable of improving the filling degree of the proppant in the fracture and the propping efficiency of the proppant is particularly important.
Disclosure of Invention
The invention aims to provide a fracturing sand adding method for an oil and gas reservoir, which is used for improving the filling degree of a proppant in a fracture and the propping efficiency of the proppant, further improving the flow conductivity of the fracture, improving the yield after fracturing and reducing the yield decreasing speed.
The oil and gas reservoir fracturing sand adding method provided by the invention comprises a pad fluid crack making stage and a sand carrying fluid sand adding stage, wherein the pad fluid crack making stage adopts first fracturing fluid and/or second fracturing fluid to inject so as to press a crack; the sand-carrying fluid sand-adding stage comprises:
the first stage of adding sand into the sand carrying liquid adopts the second fracturing fluid for injection and carries the first propping agent,
a second stage of adding sand into the sand carrying fluid, injecting the sand carrying fluid by adopting a third fracturing fluid and carrying a second propping agent,
in the third stage of adding sand into the sand carrying fluid, injecting a fourth fracturing fluid and carrying a third proppant;
the viscosity of the first fracturing fluid, the viscosity of the second fracturing fluid and the viscosity of the fourth fracturing fluid are sequentially increased, and the viscosity of the third fracturing fluid is greater than or equal to that of the second fracturing fluid and is less than that of the fourth fracturing fluid;
the particle sizes of the first proppant, the second proppant and the third proppant are sequentially increased.
According to the fracturing sand adding method provided by the invention, fracturing fluids with different viscosities and proppants with different sizes are adopted in different stages, firstly, fracturing fluid with better crack forming capability and smaller viscosity is adopted to crack in a pad stage, a proppant with smaller particle size is adopted in the sand-carrying fluid sand adding initial stage, the crack entering resistance of the proppant in the sand-carrying initial stage is reduced, then, the fracturing fluid with better sand-carrying performance and larger viscosity is added to carry the proppant with larger particle size, so that the proppants with larger particle size are reasonably configured in a crack system, and the propping effect is optimized.
According to a preferred embodiment of the invention, the second stage of sand-loading with a sand-carrying fluid comprises:
the stage A of adding sand into the sand carrying fluid, injecting the fracturing fluid A and carrying the proppant A,
adding sand into the sand carrying liquid in the stage B, injecting the fracturing liquid B and carrying the proppant B,
adding sand into the sand carrying fluid at the C stage, injecting the C fracturing fluid and carrying a C propping agent;
the viscosity of the fracturing fluid A, the viscosity of the fracturing fluid B and the viscosity of the fracturing fluid C are sequentially increased, and preferably, the viscosity of the fracturing fluid A is greater than or equal to that of the second fracturing fluid and is less than that of the fourth fracturing fluid;
the particle size of the proppant A, the proppant B and the proppant C is larger than that of the first proppant; the particle size of the proppant A, the proppant B and the proppant C is smaller than that of the third proppant; preferably the a proppant is the same as the C proppant.
The preferable embodiment further refines and optimizes the construction process, uses various types of fracturing fluids in the fracturing and sand adding process, reasonably matches and injects the propping agents with different particle sizes and different fracturing fluids, and improves the configuration effect of the propping agents, thereby improving the filling degree and the utilization rate of the propping agents.
According to a further preferred embodiment of the present invention, the sand-carrying fluid sand-adding a stage comprises:
the stage A1 of adding sand into the sand carrying liquid adopts A1 fracturing fluid to inject and carry A1 proppant,
adding sand into the sand carrying liquid at the stage A2, injecting the A2 fracturing fluid and carrying an A2 proppant;
wherein the viscosity of the A1 fracturing fluid is equal to that of the A2 fracturing fluid, preferably the A1 fracturing fluid and the A2 fracturing fluid are the same as the second fracturing fluid,
the particle size of the A1 proppant and the A2 proppant are equal, preferably the density of the A1 proppant is greater than the density of the A2 proppant, more preferably the density of the A1 proppant is greater than 1.8g/cm3Preferably at 1.8g/cm3～2.0g/cm3Range, the density of the A2 proppant is greater than 1.65g/cm3And less than 1.8g/cm3。
According to the present invention, it is preferred that the a1 proppant is the same as the C proppant.
The sand-carrying fluid sand-adding stage of the fracturing sand-adding method in the further preferred embodiment substantially comprises the following six stages:
the first stage of adding sand into the sand carrying liquid adopts the second fracturing fluid for injection and carries the first propping agent,
second stage of adding sand with sand carrying liquid
Stage A of adding sand into sand carrying liquid
The stage A1 of adding sand into the sand carrying liquid adopts A1 fracturing fluid to inject and carry A1 proppant,
the stage A2 of adding sand into the sand carrying liquid adopts A2 fracturing fluid to inject and carry A2 proppant,
adding sand into the sand carrying liquid in the stage B, injecting the fracturing liquid B and carrying the proppant B,
the C stage of adding sand into the sand carrying fluid adopts C fracturing fluid for injection and carries C propping agent,
and in a third stage of adding sand into the sand carrying fluid, injecting a fourth fracturing fluid and carrying a third proppant.
In the above further preferred embodiment of the present invention, the sanding process is further refined and optimized by injecting step by step a1 fracturing fluid, a2 fracturing fluid with better crack height retention, natural crack propagation, and branch crack after pad fracturing and first stage sand carrier injection, carrying small particle size proppant so that crack height is maintained and crack length is safely and stably maximized while proppant is smoothly and rationally distributed in different zones of the crack.
According to some preferred embodiments of the present invention, the first fracturing fluid has a viscosity in the range of 10 to 15 mPs; the viscosity of the second fracturing fluid is in the range of 30 mPS-50 mPS; the viscosity of the third fracturing fluid is within the range of 30 mPS-120 mPS; and/or the viscosity of the fourth fracturing fluid is in the range of 130 mPS-150 mPS.
In the existing fracturing sand adding method, a fracturing fluid with low viscosity is usually selected at the initial stage of fracturing sand adding, however, the use of the fracturing fluid with low viscosity at the initial stage can cause that a propping agent is prematurely settled at the bottom of a fracture seam in the propping agent migration process, so that a large amount of propping agent is prematurely accumulated at a near well fracture, the sand adding efficiency of a far well fracture in the later stage and the optimization of a sand adding section in the fracture are influenced, and the early sand plugging of construction is caused.
According to the method provided by the invention, the fracturing fluid with the viscosity ranging from 30mP & s to 50mP & s is adopted at the initial stage of the sand adding stage, so that the fracturing fluid has relatively good migration effect on the proppant and avoids the proppant from being accumulated at the near-well fracture position too early. In the second and third stages of adding sand into the sand-carrying liquid, the fracturing liquid with higher viscosity is used, the fracturing liquid has better sand-carrying performance, and can carry a proppant with larger particle size to enter the main fracture to fully support the main fracture.
According to some further preferred embodiments of the present invention, the viscosity of the a fracturing fluid is in the range of 30 to 50 mpa · s; the viscosity of the fracturing fluid B is in the range of 60 mPS-70 mPS; the viscosity of the C fracturing fluid is in the range of 100 mPS-120 mPS.
In the preferred embodiment of the invention, a variable viscosity fracturing fluid system is adopted, and 4-6 kinds of fracturing fluids with different viscosities are used. The fracturing fluid with relatively low viscosity is used for making cracks in a pad fluid stage, and then through sand adding construction in multiple stages, crack expanding and supporting are performed gradually and stably, and finally cracks with excellent flow conductivity are formed.
In some preferred embodiments of the invention, the a1 fracturing fluid is the same as the a2 fracturing fluid, with the a1 fracturing fluid and the a2 fracturing fluid being particularly preferred to be the same as the second fracturing fluid. In a particularly preferred embodiment of the invention, five types (first fracturing fluid, second fracturing fluid (a1 fracturing fluid, a2 fracturing fluid and second fracturing fluid are the same), B fracturing fluid, C fracturing fluid, fourth fracturing fluid) of fracturing fluid systems are selected. The first fracturing fluid and the second fracturing fluid have good effects of making a seam, controlling the seam height and opening and expanding a natural seam, and are used for making the seam at the front fluid seam making stage; the second fracturing fluid and the fracturing fluid B have the functions of well keeping the joint height, expanding natural cracks, branching joints and carrying small-particle-size low-sand-ratio propping agents, and can carry the propping agents with small particle sizes at the initial stage of fracturing and sand adding to fully support the micro-cracks and the branching joints; the C fracturing fluid and the fourth fracturing fluid have good sand carrying performance, and can carry a propping agent with larger particle size to fully support a main seam in the middle and later stages of fracturing main sand adding.
Fracturing fluid systems with different viscosity types are adopted in different construction stages, so that on one hand, full crack formation in a pad fluid stage is ensured, the height of a crack is controlled, and the crack formation section is optimized; on the other hand, the sand is smoothly added in the sand carrying liquid stage, the full filling of the propping agent in the fracture is realized, and the propping profile of the propping agent is optimized. In addition, by adopting liquids with different concentrations in different stages of fracturing, the damage of the liquids to the matrix and the flow conductivity of the reservoir can be reduced to the maximum extent, and the material cost is reduced.
According to some embodiments of the invention, it is preferred that the fracturing formulation used at each stage is selected from the group consisting of:
first fracturing fluid: 0.15-0.2% of SRFP-1 thickening agent, 0.3% of SRCS-1 clay stabilizer and 0.1% of SRCU-1 cleanup additive, wherein the liquid viscosity is 10 mPs-15 mPs, and the pH value is 6-7;
a second fracturing fluid: 0.25-0.3% of SRFP-1 thickening agent, 0.3% of SRCS-1 clay stabilizer and 0.1% of SRCU-1 cleanup additive, wherein the liquid viscosity is 30-50 mPs, and the pH value is 6-7;
a1 fracturing fluid: 0.25-0.3% of SRFP-1 thickening agent, 0.3% of SRCS-1 clay stabilizer and 0.1% of SRCU-1 cleanup additive, wherein the liquid viscosity is 30-50 mPs, and the pH value is 6-7;
a2 fracturing fluid: 0.25-0.3% of SRFP-1 thickening agent, 0.3% of SRCS-1 clay stabilizer and 0.1% of SRCU-1 cleanup additive, wherein the liquid viscosity is 30-50 mPs, and the pH value is 6-7;
b, fracturing fluid formula: 0.135-0.4% of SRFP-1 thickening agent, 0.3% of SRCS-1 clay stabilizer and 0.1% of SRCU-1 cleanup additive, wherein the liquid viscosity is 60-70 mPs, and the pH value is 6-7;
c, fracturing fluid formula: 0.45-0.50% of SRFP-1 thickening agent, 0.2% of SRFC-1 cross-linking agent, 0.3% of SRCS-1 clay stabilizer, 0.1% of SRCU-1 cleanup additive, the liquid viscosity of 100-120 mPs, the pH value of 6-7, and the gel breaker is Ammonium Persulfate (APS) capsule gel breaker;
and a fourth fracturing fluid formula: 0.5-0.55% of SRFP-1 thickening agent, 0.2% of SRFC-1 cross-linking agent, 0.3% of SRCS-1 clay stabilizer, 0.1% of SRCU-1 cleanup additive, the liquid viscosity is 130 mPs-150 mPs, the pH value is 6-7, and the gel breaker is Ammonium Persulfate (APS) gel breaker.
In the formula of the fracturing fluid, the percentage of the components is calculated by weight percentage. Specific components listed, for example, SRFP-1 thickener, SRCS-1 clay stabilizer, SRCU-1 cleanup additive, SRFC-1 crosslinking agent, are manufactured by petrochemical Co., Ltd., China. However, it should be noted that the components suitable for the fracturing fluid of the present invention, such as the thickener, clay stabilizer, cleanup additive, and the like, are not limited to those listed above, and may be replaced by other components commonly used in the art.
According to some preferred embodiments of the invention, the density of the first support agent is greater than or equal to 1.8g/cm3Preferably at 1.8g/cm3～2.0g/cm3A range; the density of the A1 proppant is greater than or equal to 1.8g/cm3Preferably at 1.8g/cm3～2.0g/cm3A range; the density of the A2 proppant is greater than or equal to 1.65g/cm3And less than 1.8g/cm3(ii) a The density of the B proppant is less than or equal to 1.65g/cm3Preferably at 1.0g/cm3～1.65g/cm3A range; the density of the C proppant is greater than or equal to 1.8g/cm3Preferably at 1.8g/cm3～2.0g/cm3A range; and/or the density of the third proppant is greater than or equal to 1.8g/cm3Preferably at 1.8g/cm3～2.0g/cm3And (3) a range.
According to some preferred embodiments of the present invention, the particle size of the a1 proppant, the a2 proppant, the B proppant and the C proppant is the same, and is greater than the particle size of the first proppant and less than the particle size of the third proppant. For example, in some specific embodiments, the first proppant is an 70/140 mesh ceramsite proppant, the a1 proppant, the a2 proppant, the B proppant, and the C proppant are 40/70 mesh ceramsite proppants, and the third proppant is a 30/50 mesh ceramsite proppant.
In a further preferred embodiment of the invention, the first support agent is of high density (density ≥ 1.8 g/cm)3)70/140 mesh ceramsite proppant, A1 proppant with high density (the density is more than or equal to 1.8 g/cm)3)40/70 mesh ceramsite proppant, A2 proppant with medium density (1.65 g/cm)3Less than or equal to density<1.8g/cm3) The ceramic proppant of 40/70 meshes and the proppant B has low density (the density is less than or equal to 1.65 g/cm)3) The 40/70-mesh ceramsite proppant and the C proppant are the same as the A1 proppant and have high density (the density is more than or equal to 1.8 g/cm)3)40/70 mesh ceramic proppant, and the third proppant has high density (density is more than or equal to 1.8 g/cm)3)30/50 mesh ceramsite proppant.
In accordance with the present invention, the preference of fracturing fluids and proppants can be based on two aspects: the method is based on the fracturing fluid sand carrying and sand conveying physical simulation experiment results, and is based on the simulation results of fracturing fracture simulation software, and finally, the physical simulation and fracture simulation results are integrated to preferably select the appropriate fracturing fluid and the appropriate propping agent.
According to the fracturing sand adding method provided by the invention, the different settling speeds of the propping agents and the different carrying performances of the fracturing fluid are utilized, and the propping agents with different densities are selected at different stages of sand adding, so that the filling degree and the propping efficiency of the propping agents in the fractures are improved, and the effective propping of the fractures in the far well zone is improved.
According to the preferred embodiment of the invention, the proppant with high density and small particle size (first proppant) and medium particle size (A1 proppant) is adopted at the early stage of sand adding, so that the proppant fracture which firstly enters the fracture is settled and laid at the bottom of the fracture, and the formation of a balanced sand bank is also facilitated; after the formation of the balanced sand levee, adding sand by using a medium-density medium-particle size proppant (A2 proppant) to enable the medium-density proppant to be laid in the middle of the reservoir; then, adding sand by using a low-density medium-particle-size proppant (B proppant) to ensure that the proppant is transported to a middle and far well fracture zone and realize that the upper part of the fracture is filled with the low-density proppant; and finally, adding sand by using a propping agent (C propping agent or third propping agent) with high density and medium particle size or high density and large particle size, so that the propping agent is fully filled and supported in the near-wellbore fracture zone, and the flow conductivity of the near-wellbore fracture zone is improved.
The fracture width is generally the narrowest at the initial stage of fracturing sand adding, and the fracture width shows a gradually increasing trend along with the continuous injection of fracturing fluid and the increase of injection amount; in particular, in order to control the seam height, certain reservoirs adopt fracturing fluid with relatively low viscosity to make seams, and the seam width is narrower at the initial stage of sand adding. Therefore, in the sand adding process, the particle size of the adopted proppant is gradually increased along with the gradual increase of the seam width, the proppant with small particle size (first proppant) is adopted in the initial stage, and the proppant with medium particle size (A1, A2 and B proppants) and large particle size (third proppant) are gradually adopted in the middle and later stages of sand adding, so that the matching property of the particle size of the proppant and the seam width is improved, and the construction risk is reduced.
According to some preferred embodiments of the invention, in the fracturing sand adding method provided by the invention, in the pre-fluid fracture-making stage, the injection displacement of the fracturing fluid is 40-60%, preferably 40-50% of the highest design displacement in the fracturing process, and the injection amount is 30-40% of the total injection amount in the fracturing process.
The maximum design displacement refers to that before fracturing construction, technicians in the field adopt mature fracturing fracture simulation software (such as FracPro, StimPlan, GOHFER and other software) according to reservoir geology and physical property evaluation parameter evaluation results to simulate the extension condition of fracturing fractures under various parameters such as different fracturing fluid types, fracturing fluid amounts, pad fluid ratios, fracturing displacement and the like through orthogonal design, and the maximum displacement and displacement combination is comprehensively determined by combining the fracture extension rule and the fracture section condition; the most desirable situation in fracturing is to achieve sufficient fracturing at the highest design displacement (the centerline position of the fracture must coincide or substantially coincide with the centerline position of the reservoir, and the fracture volume covers the effective reservoir thickness to the maximum extent).
According to the present invention, typically, for tight reservoirs or reservoirs with poor fluid loss, the pad fracturing stage may be injected with the first fracturing fluid at 40% to 50% of the maximum displacement. If the natural fracture of the reservoir develops or the fluid loss is large, the injection is carried out in two steps (firstly, the first fracturing fluid is used for injecting 40-50% of the highest displacement, and then the second fracturing fluid is used for injecting 50-60% of the highest displacement) or the second fracturing fluid is directly used for injecting 40-60% of the highest displacement.
In the crack making process, the crack making length comprises three stages of rapid increase, stable increase and slow increase, about 70 percent of the crack length is mainly completed in the rapid crack increase stage, and the rapid crack length increase stage can be used as the optimal preposed liquid crack making stage; therefore, the seam length of the seam at the stage is targeted to reach 70-75% of the total seam length of the fracturing design. The total fracture length of the fracturing design is based on the simulation optimization result of oil reservoir numerical software such as ECLIPSE.
According to some further preferred embodiments of the invention, in the first stage of sand-carrying fluid sand-adding, the injection displacement of the fracturing fluid is 55-65% of the maximum design displacement in the fracturing process, and the injection amount is 15-20% of the total injection amount in the fracturing process;
in the second stage of adding sand into the sand-carrying fluid, the injection displacement of the fracturing fluid is 55-100% of the highest design displacement in the fracturing process, and the injection fluid amount is 20-55% of the total injection fluid amount in the fracturing process;
in the third stage of adding sand into the sand-carrying fluid, the injection displacement of the fracturing fluid is 80-100% of the highest design displacement in the fracturing process, and the injection fluid amount is 5-10% of the total injection fluid amount in the fracturing process.
Preferably, the displacement of the third stage is greater than the displacement of the second stage.
According to some preferred embodiments of the present invention, the second stage of adding sand into the sand-carrying fluid comprises a stage a of adding sand into the sand-carrying fluid, a stage B of adding sand into the sand-carrying fluid, and a stage C of adding sand into the sand-carrying fluid. In the preferred embodiment of the present invention,
in the pre-fluid fracture-making stage, the injection displacement of the fracturing fluid is 40-60% of the highest design displacement in the fracturing process, and the injection fluid amount is 30-40% of the total injection fluid amount in the fracturing process;
in the first stage of sand carrying fluid sand adding, the injection displacement of the fracturing fluid is 55-65% of the highest design displacement in the fracturing process, and the injection fluid amount is 15-20% of the total injection fluid amount in the fracturing process;
in the stage A of adding the sand into the sand carrying liquid, the injection displacement of the fracturing liquid is 55-75% of the highest design displacement in the fracturing process, and the injection liquid amount is 15-25% of the total injection liquid amount in the fracturing process;
in the stage B of adding sand into the sand carrying liquid, the injection displacement of the fracturing liquid is 75-85% of the highest design displacement in the fracturing process, and the injection liquid amount is 10-15% of the total injection liquid amount in the fracturing process;
in the stage C of adding sand into the sand carrying liquid, the injection displacement of the fracturing liquid is 80-100% of the highest design displacement in the fracturing process, and the injection liquid amount is 5-10% of the total injection liquid amount in the fracturing process; and/or
In the third stage of adding sand into the sand-carrying fluid, the injection displacement of the fracturing fluid is 80-100% of the highest design displacement in the fracturing process, and the injection fluid amount is 5-10% of the total injection fluid amount in the fracturing process.
According to the fracturing sand adding method provided by the invention, in the fracture initiation and initial extension stages, low-displacement (40% -60% of the highest displacement) injection is carried out, so that the bottom hole pressure accumulation speed is relatively slow, and particularly for some reservoirs with poor interlayer stress shielding, the height extension of the fracture is controlled to a great extent, and the fracture-making profile optimization is facilitated. The pumping injection mode of low discharge capacity (55-65% of the highest discharge capacity) matched with low-viscosity fracturing fluid and high-density proppant is adopted in the early stage of sand adding, so that the proppant added in the early stage is favorably settled and laid at the bottom of a crack to form a balanced sand bank. After the balanced sand bank is formed, the discharge capacity (65-85 percent of the highest discharge capacity) is gradually increased in a matching manner with a pumping mode of medium-viscosity fracturing fluid and medium-low density proppant, so that the overflowing speed of the sand-carrying fluid passing through the upper part of the sand bank is gradually increased, the proppant is conveyed to a far well end crack, and the filling and supporting of the proppant for the far well zone crack are improved. After the amount of the support agent in the fractures of the far well zone meets the design requirement, the height of the sand bank is gradually reduced by matching large discharge capacity (80-100 percent of the maximum discharge capacity) with high-viscosity fracturing fluid and medium-high density support agent in a pumping mode, and the overflow speed of the sand-carrying fluid passing through the upper part of the sand bank is gradually reduced at the same time, so that more support agent is settled in the fractures of the near well zone.
According to some further preferred embodiments of the present invention, the sand-carrying fluid-sand-adding a stage comprises a sand-carrying fluid-sand-adding a1 stage and a sand-carrying fluid-sand-adding a2 stage. In this further preferred embodiment of the process according to the invention,
in the pre-fluid fracture-making stage, the injection displacement of the fracturing fluid is 40-60% of the highest design displacement in the fracturing process, and the injection fluid amount is 30-40% of the total injection fluid amount in the fracturing process;
in the first stage of sand carrying fluid sand adding, the injection displacement of the fracturing fluid is 55-65% of the highest design displacement in the fracturing process, and the injection fluid amount is 15-20% of the total injection fluid amount in the fracturing process;
in the stage A1 of adding sand into the sand-carrying liquid, the injection displacement of the fracturing liquid is 55-65% of the highest design displacement in the fracturing process, and the injection liquid amount is 10-15% of the total injection liquid amount in the fracturing process;
in the stage A2 of adding sand into the sand-carrying liquid, the injection displacement of the fracturing liquid is 65-75% of the highest design displacement in the fracturing process, and the injection liquid amount is 10-15% of the total injection liquid amount in the fracturing process;
in the stage B of adding sand into the sand carrying liquid, the injection displacement of the fracturing liquid is 75-85% of the highest design displacement in the fracturing process, and the injection liquid amount is 15-20% of the total injection liquid amount in the fracturing process;
in the stage C of adding sand into the sand carrying liquid, the injection displacement of the fracturing liquid is 80-100% of the highest design displacement in the fracturing process, and the injection liquid amount is 5-10% of the total injection liquid amount in the fracturing process; and/or
In the third stage of adding sand into the sand-carrying fluid, the injection displacement of the fracturing fluid is 80-100% of the highest design displacement in the fracturing process, and the injection fluid amount is 5-10% of the total injection fluid amount in the fracturing process.
The further optimized implementation mode further slows down the speed of displacement improvement, improves the laying effect of the high-density small-particle-size propping agent at the bottom of the small crack in the initial stage of sand adding, forms a more balanced sand bank, and lays a good foundation for the subsequent sand-carrying liquid with gradually increased displacement to smoothly and stably flow through the sand bank and gradually convey the propping agent to the cracks of the far well section for laying.
According to some preferred embodiments of the present invention, in the fracturing sand-adding method provided by the present invention,
in the first stage of sand-carrying liquid sand adding, a propping agent is added in a slug type sand adding mode, the sand-liquid ratio is in the range of 2% -12%, the sand-liquid ratio is started by 2% -6%, and 2% -5% is used as a sand adding step and is gradually increased;
in the stage of adding sand into the sand-carrying liquid A1, the propping agent is added in a slug type sand adding mode, the sand-liquid ratio is in the range of 6-16%, the sand-carrying liquid is started from 6-10%, and 2-5% is used as a sand adding step to be gradually increased;
in the stage of adding sand into the sand-carrying liquid A2, the proppant is added in a slug type sand adding mode, the sand-liquid ratio is in the range of 10-20%, the sand-liquid ratio is started by 10-15%, and 2-5% is used as a sand adding step and is gradually increased;
in the stage B of adding sand into the sand carrying liquid, the propping agent is added in a slug type sand adding mode, the sand-liquid ratio is in the range of 15-25%, the sand-liquid ratio is started from 15-20%, and 2-5% is used as a sand adding step to be gradually increased;
in the stage C of adding sand into the sand carrying liquid, the propping agent is added in a continuous, slug or spiral sand adding mode, the sand-liquid ratio is in the range of 20-30%, the sand-liquid ratio is started from 20-26%, and 2-5% is used as a sand adding step to be gradually increased; and/or
In the third stage of sand carrying liquid and sand adding, the propping agent is added in a continuous type, a slug type or a spiral type sand adding mode, the sand-liquid ratio is in the range of 20-36%, the sand-liquid ratio is started by 20-28%, and 2-5% is used as a sand adding step and is gradually increased.
According to the preferred embodiment of the invention, in each sand adding stage, the fracturing fluid used in each stage is pumped by the displacement pump, and the propping agent used in each stage is carried in the pumping process to form the sand carrying fluid.
In the first stage of sand-carrying fluid sand adding, the stage A1 and the stage A2, the sand-carrying fluid sand ratio actually adopted can be comprehensively weighed and determined in a mode of small-section plugs for testing sand adding for multiple times.
In the stage C of adding sand into the sand carrying fluid, the proppant can be preferably added in a continuous sand adding mode; if the reservoir is sensitive to high sand ratio in the sand adding process, a section plug type or spiral sand adding mode can be adopted.
In the third stage of sand-carrying fluid sand-adding, the proppant can be added in a continuous sand-adding mode; if the reservoir is sensitive to high sand ratio in the sand adding process, a section plug type or spiral sand adding mode can be adopted, and preferably when 3-5 m of propping agent remains3And continuously adding sand, and probing to quickly improve the construction sand-liquid ratio.
The fracturing sand adding method provided by the invention can further comprise a balance displacement stage, the proppant in the shaft is completely displaced to the fracture joint by adopting the first fracturing fluid, and the dosage of the fracturing fluid is the sum of the shaft volume and the ground pipeline volume.
The fracturing sand adding method provided by the invention can also comprise the steps of measuring the characteristic parameters of the storage separation layer before fracturing construction, determining the perforation position according to the measured characteristic parameters of the storage separation layer, optimizing fracturing construction parameters and implementing perforation operation.
The comprehensive evaluation of the characteristics of the storage interlayer can comprehensively adopt methods of well logging, core testing and small fracturing testing, comprehensively and deeply understand various lithology, physical properties, rock mechanics, longitudinal ground stress profile, natural fracture development characteristics and the like of the storage layer and the interlayer, and provide comprehensive and accurate basic data for the optimization of a fracturing process scheme. The specific means and process for determining the characteristic parameters of the storage and isolation layer required for the selection of the perforation position and the determination of the fracturing construction parameters are well known to those skilled in the art and will not be described herein.
The fracture-making profile of the fracture is related to factors such as the perforation position, the type of fracturing fluid, fracturing construction parameters and the like. The fracturing fluid type and proppant type as described above are selected based on reservoir property parameters in conjunction with the concepts of the present invention. The method is characterized in that the perforation position is optimized by combining the actual ground stress distribution of the storage isolation layer, fracturing fracture simulation software such as GOHFER is applied, the fracturing fluid systems (particularly the first fracturing fluid, the second fracturing fluid (A1 fracturing fluid, A2 fracturing fluid), the B fracturing fluid, the C fracturing fluid and the fourth fracturing fluid) are adopted, fracturing fracture simulation researches at different injection stages are carried out in different injection modes, and the influence of fracturing construction engineering parameter changes on fracture parameters is researched. The optimization of fracture parameters aims to make the longitudinal center line of a fracture section and the longitudinal center line of the effective thickness of a reservoir layer as close as possible. The optimization of the fracturing construction process parameters comprises the following steps: the method comprises the following steps of pre-fluid joint-making liquid amount, total fracturing injection liquid amount, fracturing liquid usage amount in different construction stages, proppant adding amount in different construction stages, lowest and highest construction discharge amount, injection discharge amount in different construction stages, sand-liquid ratio in different sand adding stages and the like. The optimal construction parameter combination can be optimized by the technicians in the field according to the actual conditions.
In the existing fracturing sand adding method, the unreasonable construction design generally exists: unreasonable optimization of fracturing construction parameters, excessive upward extension or downward extension of the fracture in the longitudinal direction of a reservoir stratum and even out-of-control fracture height, ineffective fractures cannot be fully expanded on the plane, and the ineffective fracture proportion is overlarge; in addition, the fracturing fluid ratio in the fracturing fluid fracturing stage is too low, so that the fracturing fluid fracturing is insufficient, the fracturing discharge capacity in the initial stage and the middle and later stages of sand adding is unreasonable, the sand-fluid ratio in different fracturing fluid adding stages is not properly designed or the sand-fluid ratio is too high, so that excessive propping agents are accumulated in the near well zone of the fracture, the propping efficiency of the far well fracture is low, and the propping agent distribution in the whole fracture space is extremely uneven.
In order to improve the effectiveness of reservoirs, particularly compact sandstone reservoirs and unconventional oil and gas reservoir reservoirs and improve the fracturing transformation effect, the invention provides a sand adding method which is suitable for improving the proppant filling degree and the supporting efficiency in fractures. On the basis of ensuring sufficient and effective crack formation, the change of a dynamic balance sand bank in the crack at different stages of sand addition is controlled through the optimization of the viscosity of the fracturing fluid, the particle size and the density of the propping agent, or further, the cooperative optimization of a sand adding mode and fracturing injection process parameters (construction discharge capacity, construction sand ratio and fracturing fluid quantity at different stages of construction), so that the aim of relatively uniformly laying the propping agent in the whole crack formation crack space is fulfilled, the filling degree and the propping efficiency of the propping agent in the crack are improved, and the effectiveness of fracturing transformation is improved.
The sand adding method for improving the proppant filling degree and the proppant propping efficiency in the fracture is simple in thought and convenient to operate and implement on site. The method aims at digging the yield increasing potential of the reservoir to the maximum extent within the limited thickness range of the reservoir, improves the fracturing modification volume on the basis of full fracture forming through the optimization of a fracturing fluid system, the optimization of a propping agent and the collaborative simulation optimization of multiple parameters of the fracturing construction project, fully expands the fracture, realizes the effective filling and the effective supporting of the propping agent in the fracturing fracture forming space, and improves the supporting efficiency of the whole fracture system and the effective flow conductivity of the pressed fracture. The method can effectively solve the problems of low initial yield, fast yield decrease, short stable production period and the like after the fracturing, and improve the fracturing modification effect and the exploitation degree of the reservoir.
On-site tests prove that after the fracturing method is adopted, the long-term flow conductivity of the fracture is obviously improved, the yield increase amplitude after fracturing is greatly improved, the stable production period is obviously better than that of a conventional fracturing mode, and the development benefits of the compact sandstone and the unconventional oil and gas reservoirs are improved.
Drawings
FIG. 1 is an explanatory result diagram of the stress profile of a fracturing target zone of an X well.
FIG. 2 shows the optimization result of the stress fracture length of the X well fracturing target stratum.
FIG. 3 is a cross-sectional view of the X-well fracturing target zone perforation position and parameter optimization front and back fractures.
Detailed Description
The invention will be further illustrated by the following specific examples. It is to be understood, however, that the following examples are intended to further illustrate the invention, but are not to be construed as limiting the invention.
The X well is a typical dense gas reservoir evaluation well, and the target layer fracturing well section is 3250.7-3261.5 m and 10.8m/1 layer; wellbore volume 15m3(ii) a The lithology of the target interval is gray sandstone containing gravel, the average porosity is 9.73 percent, the permeability is 0.259mD, the pressure coefficient is 1.0, and the temperature is 120 DEG CThe low-porosity ultra-low-permeability normal-temperature normal-pressure gas reservoir is a low-porosity ultra-low-permeability normal-temperature normal-pressure gas reservoir.
In order to evaluate the gas content and the productivity of a target layer sand group, the fracturing scheme design and the field pilot test of the well are carried out by taking the process method provided by the invention as reference and combining the actual condition of the well, and the specific implementation method and the effect are as follows.
(1) Comprehensive evaluation of storage interlayer ground stress
In addition to the above characteristic parameters of the X well, according to the stress profile explanation, the minimum principal stress mean value of the target layer of the well is 44.1MPa, the minimum principal stress number mean value of the upper interlayer of the target layer is 47.5MPa, and the minimum principal stress mean value of the lower interlayer is 49.7 MPa. The results of the interpretation of the stress profile of the target zone of the fracture of this well are shown in figure 1 (the last column shows the minimum principal stress variation).
(2) Fracturing fracture parameter optimization simulation
The ECLIPSE reservoir numerical software simulation software is adopted to carry out optimization simulation on fracture parameters, and the simulation shows that (shown in figure 2): the well target zone production increases with increasing fracture half-length; when the half length of the crack is more than 200m, the accumulated yield is gradually reduced, and the optimal half length of the crack is recommended to be about 240m by comprehensive consideration.
(3) Perforation position and fracturing construction parameter simulation optimization
By combining the actual ground stress distribution of the X-well target reservoir interlayer, applying fracturing fracture simulation software such as GOHFER and the like, and adopting five types of fracturing fluid systems (i fracturing fluid, ii fracturing fluid, iii fracturing fluid, iv fracturing fluid and v fracturing fluid) and propping agents, the fracturing perforation positions and parameters (attached table 1 and attached table 3), the fracturing fracture sections and the fracturing construction parameters are comprehensively simulated and optimized.
A fracturing fluid system:
formula of No. I fracturing fluid: 0.2% of SRFP-1 thickening agent, 0.3% of SRCS-1 clay stabilizer and 0.1% of SRCU-1 cleanup additive, the liquid viscosity is 10 mPs-15 mPs, and the pH value is 6-7;
formula of fracturing fluid II: 0.3 percent of SRFP-1 thickening agent, 0.3 percent of SRCS-1 clay stabilizer and 0.1 percent of SRCU-1 cleanup additive, the liquid viscosity is 30 mPs-50 mPs, and the pH value is 6-7;
formula of No. III fracturing fluid: 0.4% of SRFP-1 thickening agent, 0.3% of SRCS-1 clay stabilizer and 0.1% of SRCU-1 cleanup additive, wherein the liquid viscosity is 60 mPs-70 mPs, and the pH value is 6-7;
and IV fracturing fluid formula: 0.50% of SRFP-1 thickening agent, 0.2% of SRFC-1 cross-linking agent, 0.3% of SRCS-1 clay stabilizer, 0.1% of SRCU-1 cleanup additive, the liquid viscosity of 100mP & s-120 mP & s, the pH value of 6-7, and the gel breaker is Ammonium Persulfate (APS) capsule gel breaker;
the formula of the No. V fracturing fluid comprises the following components: 0.55% of SRFP-1 thickening agent, 0.2% of SRFC-1 cross-linking agent, 0.3% of SRCS-1 clay stabilizer, 0.1% of SRCU-1 cleanup additive, the liquid viscosity of 130mP & s-150 mP & s, the pH value of 6-7, and the gel breaker is Ammonium Persulfate (APS) capsule gel breaker.
The thickener, clay stabilizer, cleanup additive, crosslinking agent, etc. used above are produced by petrochemical corporation of China.
A proppant system:
a, proppant: high density (density is more than or equal to 1.8 g/cm)3)70/140 mesh ceramsite proppant;
b, proppant: high density (density is more than or equal to 1.8 g/cm)3)40/70 mesh ceramsite proppant;
c, proppant: medium density (1.65 g/cm)3Less than or equal to density<1.8g/cm3)40/70 mesh ceramsite proppant;
d, proppant: low density (density is less than or equal to 1.65 g/cm)3)40/70 mesh ceramsite proppant;
e, proppant: high density (density is more than or equal to 1.8 g/cm)3)30/50 mesh ceramsite proppant.
The optimization results (see fig. 3) are: total amount of fracturing fluid 995m3Wherein the fracturing fluid No. I is 320m3No. II fracturing fluid 400m3No. III fracturing fluid 120m3IV fracturing fluid 80m3No. V fracturing fluid 60m3(ii) a Fracturing fluid 320m for crack formation by pad fluid3Accounting for 32% of the total fracturing fluid volume. Total proppant amount 72.0m3Wherein a proppant 6.3m3B proppant 20.7m3C proppant 11.8m3D proppant 16.3m3E proppant 16.9m3(ii) a Minimum discharge capacity of 2.5m3Min, maximum discharge capacity 6.0m3/min。
Attached table 1X well fracturing target layer perforation optimization result
| Perforation scheme | Perforation well section (m) | Thickness (m) | Gun shape | Bullet type | Density (holes/m) | Number of holes (number) | Phase (o) |
| Before optimization | 3250.7～3261.5 | 10.8 | 102 | 127 | 16 | 173 | 90 |
| After optimization | 3255.5～3261.5 | 6.0 | 102 | 127 | 16 | 96 | 60 |
(4) Pre-liquid seam making stage
At 2.5m3Permin displacement injection 120m3Fracturing fluid No. I (first fracturing fluid), then at 3.0m3Permin displacement injection 200m3Fracturing fluid No. ii (second fracturing fluid).
(5) Sand-adding stage of sand-carrying liquid
At 3.5m3Permin displacement injection 160m3Adding a propping agent (a first propping agent) in a slug type sand adding mode in the injection process of the fracturing fluid II, wherein the propping agent (a) is added in the slug type sand adding mode together with a propping agent of 6.3m in a step increasing mode (3-5-8-10%) at a sand ratio starting sand ratio of 3 percent3；
At 3.5m3Permin displacement injection 120m3Adding proppant b (A1 proppant) in a slug type sand adding mode in the injection process of the fracturing fluid II, starting the sand ratio at 8 percent in the slug type sand adding mode, and adding the proppant b 7.3m in a step increasing mode (8 to 10 to 12 percent) in total3；
At 4.0m3Permin displacement injection 120m3Adding a c proppant (A2 proppant) in a slug type sand adding mode in the injection process of the No. II fracturing fluid, starting the sand ratio at a sand ratio of 14 percent in the slug type sand adding mode, and adding 11.8m of the c proppant in a step increasing mode (14-16-18 percent) in total3；
At 5.0m3Permin displacement injection 120m3In the No. III fracturing fluid, a d proppant (B proppant) is added in a slug type sand adding mode in the injection process, the d proppant is added in 16.3m in the slug type sand adding mode in a step increasing mode (20-22-24%) with the starting sand ratio of 18 percent3；
At 6.0m3Permin displacement injection 80m3IV fracturing fluid, b proppant (C proppant/A1 proppant) is added in a slug type sand adding mode in the injection process, and the slug type sand adding mode starts to work at a sand ratio of 26 percentThe sand ratio is that b proppant 13.4m is added in a step increasing mode (26-28 percent)3；
At 6.0m3Permin displacement injection 60m3Adding an e proppant (third proppant) in a continuous sand adding mode in the No. V fracturing fluid in the injection process, starting the sand ratio at a sand ratio of 26 percent in a slug type sand adding mode, and adding 16.9m of the e proppant in a step increasing mode (26-28-32 percent) in total3。
(6) Equilibrium displacement phase
At 6.0m3The displacement per minute is pumped into a pump with the displacement of 15.0m3And (3) carrying out balance displacement on the No. I fracturing fluid, stopping the pump after the displacement is finished, measuring the pressure drop for 2 hours, and then finishing the well construction.
The inversion fracture-making profile of the fracture after the X-well fracturing construction is ideal, and the well temperature logging explains that the height of the fracture is 80 percent and extends in the longitudinal range of the reservoir, which indicates that the construction middle joint height is well controlled; in the fracturing construction, the propping agents with different particle sizes are smoothly added into fractures with different sizes, the fracture inversion propping agents are uniformly laid in the whole fracture-making fracture space in the transverse direction, the filling degree in the longitudinal direction is high, and the effective propping rate of the propping agents to a reservoir is good. According to trial production statistics after well pressure, the daily gas volume at the initial stage reaches 30000-45000 m3D, the daily volume after stable production is stabilized at 20000-25000 m3The yield of the well is about 2 to 3 times of the yield of the adjacent well in the area in the conventional fracturing process; the incremental deceleration rate of the output of the test well after being pressed is obviously slowed down, the effective period is prolonged by more than 50 percent, and the fracturing yield-increasing and yield-stabilizing effects are improved.
Although the present invention has been described in detail, modifications within the spirit and scope of the invention will be apparent to those skilled in the art. Further, it should be understood that the various aspects recited herein, portions of different embodiments, and various features recited may be combined or interchanged either in whole or in part. In the various embodiments described above, those embodiments that refer to another embodiment may be combined with other embodiments as appropriate, as will be appreciated by those skilled in the art. Furthermore, those skilled in the art will appreciate that the foregoing description is by way of example only, and is not intended to limit the invention.
Claims (11)
1. A fracturing sand adding method for oil and gas reservoirs comprises a pre-fluid crack making stage and a sand carrying and adding stage,
in the pre-fluid crack making stage, a first fracturing fluid and a second fracturing fluid are injected to crack;
the sand-carrying fluid sand-adding stage comprises:
the first stage of adding sand into the sand carrying liquid adopts the second fracturing fluid for injection and carries the first propping agent,
a second stage of adding sand into the sand carrying fluid, injecting the sand carrying fluid by adopting a third fracturing fluid, carrying a second proppant, and
in the third stage of adding sand into the sand carrying fluid, injecting a fourth fracturing fluid and carrying a third proppant;
the viscosity of the first fracturing fluid, the viscosity of the second fracturing fluid and the viscosity of the fourth fracturing fluid are sequentially increased, and the viscosity of the third fracturing fluid is greater than or equal to that of the second fracturing fluid and is less than that of the fourth fracturing fluid;
the particle sizes of the first proppant, the second proppant and the third proppant are sequentially increased;
the viscosity of the first fracturing fluid is within the range of 10-15 mPS, the viscosity of the second fracturing fluid is within the range of 30-50 mPS, the viscosity of the third fracturing fluid is within the range of 30-120 mPS, and the viscosity of the fourth fracturing fluid is within the range of 130-150 mPS.
2. The method of claim 1, wherein the second stage of sand-loading with sand-laden fluid comprises:
the stage A of adding sand into the sand carrying fluid, injecting the fracturing fluid A and carrying the proppant A,
adding sand into the sand carrying liquid in the stage B, injecting the fracturing liquid B and carrying the proppant B,
adding sand into the sand carrying fluid at the C stage, injecting the C fracturing fluid and carrying a C propping agent;
the viscosity of the fracturing fluid A, the viscosity of the fracturing fluid B and the viscosity of the fracturing fluid C are sequentially increased, and the viscosity of the fracturing fluid A is greater than or equal to that of the second fracturing fluid and is less than that of the fourth fracturing fluid;
the particle size of the proppant A, the proppant B and the proppant C is larger than that of the first proppant; the particle size of the a proppant, the B proppant, and the C proppant is less than the particle size of the third proppant.
3. The method of claim 2, wherein the sand-carrying fluid sanding stage a comprises:
the stage A1 of adding sand into the sand carrying liquid adopts A1 fracturing fluid to inject and carry A1 proppant,
adding sand into the sand carrying liquid at the stage A2, injecting the A2 fracturing fluid and carrying an A2 proppant;
wherein the viscosity of the A1 fracturing fluid is equal to that of the A2 fracturing fluid,
the particle size of the A1 proppant and the A2 proppant were equal;
the a1 proppant was the same as the C proppant.
4. The method of claim 3 wherein the A1 fracturing fluid and the A2 fracturing fluid are the same as the second fracturing fluid and the density of the A1 proppant is greater than the density of the A2 proppant.
5. The method of claim 4 wherein the density of the A1 proppant is at 1.8g/cm3～2.0g/cm3In the range of (1), the density of the A2 proppant is greater than 1.65g/cm3And less than 1.8g/cm3。
6. The method of any one of claims 2 to 5, wherein the viscosity of the A fracturing fluid is in the range of 30 mPs to 50 mPs; the viscosity of the fracturing fluid B is in the range of 60 mPS-70 mPS; the viscosity of the C fracturing fluid is in the range of 100 mPS-120 mPS.
7. The method according to any one of claims 3 to 5,
the density of the first supporting agent is 1.8g/cm3～2.0g/cm3A range;
the density of the A1 proppant was 1.8g/cm3～2.0g/cm3A range;
the density of the A2 proppant is greater than or equal to 1.65g/cm3And less than 1.8g/cm3；
The density of the B proppant is 1.0g/cm3～1.65g/cm3A range;
the density of the C proppant is 1.8g/cm3～2.0g/cm3A range; and/or
The density of the third proppant is 1.8g/cm3～2.0g/cm3And (3) a range.
8. The method according to claim 1, characterized in that in the pre-fluid fracture-making stage, the injection displacement of the fracturing fluid is 40-60% of the maximum design displacement in the fracturing process, and the injection amount is 30-40% of the total injection amount in the fracturing process;
in the first stage of sand carrying fluid sand adding, the injection displacement of the fracturing fluid is 55-65% of the highest design displacement in the fracturing process, and the injection fluid amount is 15-20% of the total injection fluid amount in the fracturing process;
in the second stage of adding sand into the sand-carrying fluid, the injection displacement of the fracturing fluid is 55-100% of the highest design displacement in the fracturing process, and the injection fluid amount is 20-55% of the total injection fluid amount in the fracturing process;
in the third stage of adding sand into the sand-carrying fluid, the injection displacement of the fracturing fluid is 80-100% of the highest design displacement in the fracturing process, and the injection fluid amount is 5-10% of the total injection fluid amount in the fracturing process.
9. The method according to claim 3, wherein in the pre-fluid fracture-making stage, the injection displacement of the fracturing fluid is 40-60% of the maximum design displacement in the fracturing process, and the injection amount is 30-40% of the total injection amount in the fracturing process;
in the first stage of sand carrying fluid sand adding, the injection displacement of the fracturing fluid is 55-65% of the highest design displacement in the fracturing process, and the injection fluid amount is 15-20% of the total injection fluid amount in the fracturing process;
in the stage A1 of adding sand into the sand-carrying liquid, the injection displacement of the fracturing liquid is 55-65% of the highest design displacement in the fracturing process, and the injection liquid amount is 10-15% of the total injection liquid amount in the fracturing process;
in the stage A2 of adding sand into the sand-carrying liquid, the injection displacement of the fracturing liquid is 65-75% of the highest design displacement in the fracturing process, and the injection liquid amount is 10-15% of the total injection liquid amount in the fracturing process;
in the stage B of adding sand into the sand carrying liquid, the injection displacement of the fracturing liquid is 75-85% of the highest design displacement in the fracturing process, and the injection liquid amount is 10-15% of the total injection liquid amount in the fracturing process;
in the stage C of adding sand into the sand carrying liquid, the injection displacement of the fracturing liquid is 80-100% of the highest design displacement in the fracturing process, and the injection liquid amount is 5-10% of the total injection liquid amount in the fracturing process;
in the third stage of adding sand into the sand-carrying fluid, the injection displacement of the fracturing fluid is 80-100% of the highest design displacement in the fracturing process, and the injection fluid amount is 5-10% of the total injection fluid amount in the fracturing process.
10. The method of claim 8,
in the first stage of sand-carrying liquid sand adding, a propping agent is added in a slug type sand adding mode, the sand-liquid ratio is in the range of 2% -12%, the sand-liquid ratio is started by 2% -6%, and 2% -5% is used as a sand adding step and is gradually increased;
in the stage of adding sand into the sand-carrying liquid A1, the propping agent is added in a slug type sand adding mode, the sand-liquid ratio is in the range of 6-16%, the sand-carrying liquid is started from 6-10%, and 2-5% is used as a sand adding step to be gradually increased;
in the stage of adding sand into the sand-carrying liquid A2, the proppant is added in a slug type sand adding mode, the sand-liquid ratio is in the range of 10-20%, the sand-liquid ratio is started by 10-15%, and 2-5% is used as a sand adding step and is gradually increased;
in the stage B of adding sand into the sand carrying liquid, the propping agent is added in a slug type sand adding mode, the sand-liquid ratio is in the range of 15-25%, the sand-liquid ratio is started from 15-20%, and 2-5% is used as a sand adding step to be gradually increased;
in the stage C of adding sand into the sand carrying liquid, the propping agent is added in a continuous, slug or spiral sand adding mode, the sand-liquid ratio is in the range of 20-30%, the sand-liquid ratio is started from 20-26%, and 2-5% is used as a sand adding step to be gradually increased;
in the third stage of sand carrying liquid and sand adding, the propping agent is added in a continuous type, a slug type or a spiral type sand adding mode, the sand-liquid ratio is in the range of 20-36%, the sand-liquid ratio is started by 20-28%, and 2-5% is used as a sand adding step and is gradually increased.
11. The method of claim 1, further comprising a balanced displacement stage wherein the proppant in the wellbore is completely displaced to the fracture site with a first fracturing fluid, the amount of fracturing fluid being the sum of the wellbore volume and the surface line volume.
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